Coiled tubing refers to metal piping, used for interventions in oil and gas wells and sometimes as production tubing in depleted gas wells. Coiled tubing operations typically involve at least three primary components. The coiled tubing itself is spooled on a large reel and is dispensed onto and off of the reel during an operation. The tubing extends from the reel to an injector. The injector moves the tubing into and out of the wellbore. Between the injector and the reel is a tubing guide or gooseneck. The gooseneck is typically attached or affixed to the injector and guides and supports the coiled tubing from the reel into the injector. Typically, the tubing guide is attached to the injector at the point where the tubing enters. As the tubing wraps and unwraps on the reel, it moves from one side of the reel to the other (side-to-side).
Residual bending is one of the technical challenges for coiled tubing operations. Residual bend exists in every coiled tubing string. During storage and transportation, a coiled-tubing string is plastically deformed (bent) as it is spooled on a reel. During operations, the tubing is unspooled (bent) from the reel and bent on the gooseneck before entering into the injector and the wellbore. Although the reel is manufactured in a diameter as large as possible to decrease the residual bending incurred on the coiled tubing, the maximum diameter of many reels is limited to several meters due to storage and transportation restrictions.
As the coiled tubing goes through the injector head, it passes through a straightener; but the tubing retains some residual bending strain. That strain can cause the tubing to wind axially along the wall of the wellbore like a long, stretched spring. In conventional coiled tubing operations, the tubing is translated along the borehole either via gravity or via an injector pushing from the surface. As a result, the end of the coiled tubing being translated into the borehole is load-free. For an extended reach horizontal wellbore, an axial compressive load will build up along the length of the coiled tubing due to frictional interactions between the coiled tubing and the borehole wall. As the borehole “doglegs” away from the vertical direction, the axial load changes in a tensile direction. A typical axial load as a function of measured depth in a wellbore is plotted in FIG. 1 where the wellbore has a 4000 foot vertical section; a 600 foot, 15 degree per 100 foot dogleg section from vertical to horizontal; and a horizontal section that extends to the end of the wellbore.
When a long length of coiled tubing is deployed in the horizontal portion of the well bore, frictional forces are exerted on the tubing string from the wellbore wall rubbing on the coiled tubing, increasing the axial compressive load. If the horizontal section of the wellbore is sufficiently long, the axial compressive load will be large enough to cause the coiled tubing to buckle. A first buckling mode of the tubing string is referred to as “sinusoidal buckling”. In the first buckling mode, the coiled tubing snakes along the bottom of the borehole with curvature in alternating senses. This is a fairly benign buckling mode, in the sense that neither the internal stresses nor frictional loads increase significantly.
A second buckling mode is termed “helical buckling”. The helical buckling mode is characterized by the coiled tubing spiraling or wrapping along the borehole wall. Helical buckling can have quite severe consequences. For example, once the coiled tubing begins to buckle helically, the normal force exerted by the borehole wall on the coiled tubing string increases very quickly. This causes a proportional increase in frictional loading, which consequently creates an increase in axial compressive load in the tubing string between the injector and the end of the helically buckled region. Once helical buckling has been initiated, further injection of the tubing causes that axial compressive load to increase sharply with injection to a level that indicates that the tubing string is in a condition termed “lock-up”. Visually, the lock-up condition can be noted at the top of the wellbore when the tubing string contacts the wall of the wellbore or well casing. A plot of axial load as a function of measured depth for a coiled tubing, which is almost in a locked up state is shown in FIG. 2. Such lock-up limits the use of coiled tubing as a conveyance member for logging tools in highly-deviated, horizontal, or up-hill sections of wellbores.
Various methods are available to avoid lock-up and extend the reach of coiled tubing. Some of these methods include tractors, tapered coiled tubing strings, alternate materials e.g. composite coiled tubing, straighteners, friction reducers, and injecting a light fluid inside the coiled tubing. These methods are aimed at delaying the onset of helical buckling, which, as described above, may lead to lock-up of the coiled tubing string.